Exploring, drilling and completing hydrocarbon and other wells are generally complicated and ultimately very expensive endeavors. In recognition of the potentially enormous expenses involved, added emphasis is regularly placed on streamlining the processes of drilling, completions, and even intervening well applications which require some degree of access. That is, by streamlining the amount of time and equipment employed over the course of various drilling, completions and interventions, a dramatic effect on the overall amount of expenses consumed by a given well may be realized.
One manner by which streamlining of well applications is often pursued is in the area of interventions. So, for example, where a wellbore operation such as a well treatment application is to be run, mobile coiled tubing equipment may be employed. That is, rather than reconstruct a large scale rig over the well to support a subsequent treatment application, a relatively mobile coiled tubing truck and injector may be delivered to the well site. Thus, coiled tubing from a reel at the truck may be run through the injector and advanced into the well to a treatment location therein.
The ‘rig-less’ nature of coiled tubing as described above, may save a degree of time and equipment expenses in avoiding a complete up-rigging of tools. Nevertheless, a fair amount of equipment is located at the well site, such as the noted injector and pressure control equipment (often referred to as a blow-out preventor (BOP) stack). Furthermore, a multi-tool toolstring of variable diameter is located at the end of the coiled tubing and must be run through the BOP, tool by tool, in order to be made available for advancement to the treatment location.
Unfortunately, a whole host of well, tool and downhole device diameter issues present challenges to completions and interventional applications, streamlined or otherwise. With specific reference to a coiled tubing treatment as noted above, the variable diameter toolstring may require as much as two hours per tool to load through the BOP. This is due to each tool being individually loaded and coupled to the next tool and/or coiled tubing end, so as to maintain controlled pressurization. All in all, depending on the length of the toolstring and number of tools involved, it may take about 15-30 hours to completely load the toolstring. At an average cost of about $50,000 per hour, simply equipping the site for the treatment application may become extremely expensive.
Other forms of completions or interventional streamlining may also face certain diameter-related challenges or limitations even after downhole access is successfully achieved. One such limitation, relates to the general requirement that downhole device fixtures be deployed in a bottom-up fashion. So, for example, where multiple packers are to be deployed and left in a well for zonal isolation, the downhole packer is first deployed, followed by the deployment of a more uphole packer. That is, unlike a spot treatment, the deployment of a fixture such as the initially deployed packer would present an obstacle to later deployment of a packer further downhole. Thus, where a fixture is to be deployed, it is deployed after all further downhole access is completed.
Unfortunately, requiring access take place in a particular sequential order, such as the above-noted bottom-up access, places a significant limitation on operational flexibility. For example, in the noted case of packer deployment, the placement of the first packer serves as an obstruction preventing delivery of another packer or tool downhole of the initial packer. Thus, in order to access regions of the well below a fixed packer, a packer removal application must first be run. Similar scenarios hold true for a variety of downhole fixtures. For example, in the area of completions, once production tubing is firmly affixed downhole, the possibility of extending the depth of production tubing is hampered by the fixed presence of the production tubing already in place.
Any number of additional well, tool, and device diameter-related issues arise on a regular basis at the oilfield. Indeed, even the presumed diameter of the well itself generally varies by as much as a couple of inches. All in all, operators are faced with diameter-related challenges from the time deployment equipment outside of the well is utilized until post-completion access is sought and everywhere in between. As a result, significant practical limitations exist when attempting to employ flexibility or streamline such applications.